Genetic mechanism of deep zeolite-rich reservoirs: a case study of the Lower Wuerhe Formation in Junggar Basin

Abstract

With continued exploration and the increased need for energy resources, deep reservoirs have gradually become the main target of oil and gas exploration in recent years. The Lower Wuerhe Formation on the northern slope of the Central Depression of the Junggar Basin has a high-quality, deep, glutenite (coarse-grained clastic) reservoir at depths greater than 4500 m. However, its genetic mechanism remains unclear. Here, we improve our understanding of the origin of this deep reservoir by performing comprehensive investigations via thin section analysis, field emission scanning electron microscopy, electron probe analysis, X-ray diffraction analysis, and whole-rock carbon and oxygen isotope analysis. The results reveal that the deep reservoir lithology within the study area comprises primarily gray-white gravelly gritstone and conglomerate. Zeolite cement is predominant, and secondary dissolution pores are the primary type of reservoir space in deep reservoirs. The Lower Wuerhe Formation has experienced significant compaction in the study area. Debris flow microfacies serve as the prevailing sedimentary microfacies containing substantial amounts of laumontite. The effect of dissolution of organic acids on laumontite is pivotal in the formation of high-quality deep reservoirs in the study area. These findings serve as valuable references for the genesis of deep zeolite-rich reservoirs in the Central Depression of the Junggar Basin and other areas worldwide.

Graphical abstract

Keywords

deep reservoirs / laumontite / organic acid fluids / Lower Wuerhe Formation / Junggar Basin / genesis

1 Introduction

Oil and gas reservoirs in deep layers have gradually become important targets for exploration worldwide. Many deep oil and gas reservoirs have been discovered. For example, the burial depth of the target layer of the Kaskida oil and gas field in the Gulf of Mexico is 7356 m (Jia et al., 2011), that of the Washington oil field is 6540 m (Zhang et al., 2014), that of the Mills Ranch Field in the Anadarko sag ranges from 7663 m to 8103 m (Aase and Walderhaug, 2005), and that of the deep gas field under the Kelasu salt in the Tarim Basin is 7000 m (Pang, 2010). However, the genetic mechanism of deep reservoirs is very complex and varies from formation to formation. For example, the glutenite (coarse-grained clastic) reservoirs of the Kongdian Formation in the south-west Bozhong sag represent a typical sieve-like pore deposit. Its characteristics are influenced primarily by subsequent dissolution processes (Hou et al., 2019). However, the main factors controlling the physical properties of deep reservoirs in the Wufeng–Longmaxi Formations within the Sichuan Basin are predominantly related to sedimentary facies, such as the formation pressure coefficient and the presence of a deep-water microfacies sedimentary environment enriched with organic acids (Gao et al., 2022). The physical properties of deep reservoirs in the northern margin of the Qaidam Basin are controlled mainly by sedimentation, diagenesis, and abnormally high-elevation zones (Tian et al., 2022). Therefore, because of the uncertainty of deep reservoir genesis, it is necessary to further study the main factors controlling deep reservoirs on a case-by-case basis.

The Permian strata within the Junggar Basin are widely distributed and are important for exploration endeavors. As exploration in the Junggar Basin continues to advance, a burgeoning focus has been on probing deep reservoirs (He et al., 2021a). In the Junggar Basin, reservoirs buried more than 4500 m are usually regarded as deep layers by predecessors and have been continuously investigated in previous studies (Yao et al., 2018; Li et al., 2020b; Long et al., 2021; Huang et al., 2024; Liu et al., 2025). In recent years, notable oil and gas reservoirs have been discovered across a vast expanse within the middle and shallow layers of the Permian Wuerhe Formation, encompassing an expansive exploration area of approximately 1060 km². Moreover, the Lower Wuerhe Formation presents a resource potential capable of fostering substantial oil and gas fields (He et al., 2021b), indicating promising exploration prospects (Tang et al., 2023).

Previous studies have shown that fan delta sedimentary systems have developed in the Lower Wuerhe Formation in the Junggar Basin and that the lithology is dominated by glutenite (Pang, 2015), which is mainly rich in zeolite (Wang et al., 2018). The deep reservoirs in the basin exhibit obvious low-porosity and low-permeability characteristics (Qian et al., 2021a; Liu et al., 2024). The deep reservoirs of the Lower Wuerhe Formation have undergone various diagenetic processes, including compaction (Fu et al., 2019; Zou et al., 2021), cementation (Wang et al., 2018), and dissolution (Jiang et al., 2012; Wang et al., 2022a). Some scholars have suggested that low geothermal gradients and increased contents of rigid particles increase the number of primary pores in deep reservoirs, and these factors are the main factors controlling the formation process of high-quality deep reservoirs in the Lower Wuerhe Formation (Lei et al., 2020; Wang et al., 2022b). Moreover, some scholars have suggested that the shrinkage of zeolite during diagenesis increases secondary pores in deep reservoirs, where this factor is the main factor controlling the formation of high-quality deep reservoirs in the Lower Wuerhe Formation (Aase and Walderhaug, 2005). Most scholars have suggested that the dissolution of fluids in deep reservoirs is the greatest influence (Xu et al., 2018; Zhang et al., 2022; Han et al., 2023). However, sufficient evidence that dissolution is the main factor controlling high-quality deep reservoirs in the relevant formations is lacking. Moreover, the principal components of the acidic fluids involved in dissolution in the deep reservoirs of this formation have not been determined. In addition, although the presence of zeolites in the deep zeolite-rich reservoirs of the research area leads to complexity of soluble components in deep reservoirs (Meng et al., 2020), the genetic mechanisms of the deep reservoirs in the research area are diverse (Chen et al., 2014; Yuan et al., 2015), and the main dissolved components in the deep reservoirs have not yet been revealed. In summary, research on diagenesis and the genetic mechanism of high-quality deep reservoirs is urgently needed.

In this study, microscopic identification, C-O isotope analysis, field emission scanning electron microscopy (FE-SEM), electron probe microanalysis (EPMA), and X-ray diffraction (XRD), along with other rock‒mineral analysis methods, were used to clarify the characteristics of physical properties and genesis of the deep glutenite reservoir in the Lower Wuerhe Formation on the northern slope of the central depression area. The mechanisms underlying the effects of the sedimentary environment and diagenesis on the physical properties of reservoirs are coupled, and their patterns of distribution are analyzed. This work provides a reference for the characteristics and genesis of deep zeolite-rich reservoirs worldwide.

2 Geological setting

The Junggar Basin is in north-western China and partially in the Xinjiang Uygur Autonomous Region. It is China’s second-largest sedimentary basin (Li et al., 2020a; Qian et al., 2021b). The north-eastern region is adjacent to the Chingrid Mountains and the Kelamei Mountains, the western region is adjacent to the Zaire Mountains and the Hala’alat Mountains, and the southern region is adjacent to the north Tianshan Mountains and the Bogda Mountains (Fig. 1). The basin is approximately 700 km in length from east to west, 370 km in width from north to south, and encompasses an area of 136000 km².

The central depression zone is located in the middle of the basin, including five uplifts and five sags, for a total of ten secondary tectonic units, covering the main hydrocarbon-generating sags of the basin (Yin et al., 2008). Since the late Hercynian, the basin has experienced four tectonic stages—Hercynian, Indosinian, Yanshan, and Himalayan—and three basin stages—foreland, depression, and foreland. Under the transformation of multistage tectonic movements, a series of unconformity surfaces and faults have formed in the central depression area, and these surfaces and faults can provide a system for transporting oil and gas, and its peripheral structures have extraordinary oil and gas exploration potential (Ma et al., 2021).

The study area is located within the northern slope region of the central depression, which is located on the north-west margin of the Junggar Basin (Fig. 1). The northern slope area, which trends in a north-east‒south-west direction, is adjacent to the Wuxia thrust fracture zone and Kebai fracture zone on the north-west margin. The structural and sedimentary evolution of this area has been influenced primarily by the thrust fracture zone on the north-west margin (Yuan et al., 2017; Qian et al., 2021a).

The stratigraphy in the study area exhibits a relatively complete sequence, with formations arranged from bottom to top as follows: the Permian Fengcheng Formation (P₁f), Xiazijie Formation (P₂x), and Lower Wuerhe Formation (P₂w); the Triassic Baikouquan Formation (T₁b), Karamay Formation (T₂k), and Baijiantan Formation (T₃b); the Jurassic Badaowan Formation (J₁b), Sangonghe Formation (J₁s), Xishanyao Formation (J₂x), and Toutunhe Formation (J₂t); the Cretaceous Tugulu Group (K₁tg), Ailik Lake Formation (K₂a), and Hongyishan Formation (K₂h); the Palaeogene Ziniquanzi Formation (E_1-2z) and Anjihaihe Formation (E_2-3a); the Neogene Shawan Formation (N₁s), Tasihe Formation (E₃N₁s), and Dushanzi Formation (N₂d); and the Quaternary Xiyu Formation (Q₁x). All of these formations have regional unconformities between the Carboniferous and Permian, Permian and Triassic, Triassic and Jurassic, Jurassic, and Cretaceous, and Palaeogene and Neogene strata (Xia et al., 2012). The Lower Wuerhe Formation in the research area is in conformable contact with the underlying Xiazijie Formation (Chen et al., 2003) and is in unconformable contact with the overlying Baikouquan Formation (Wu et al., 2022). The Lower Wuerhe Formation can be subdivided into four sections: the first section (P₂w₁), the second section (P₂w₂), the third section (P₂w₃), and the fourth section (P₂w₄).

The Junggar Basin strata were deposited in a continental sedimentary environment with relatively active diastrophism, resulting in the formation of a faulted basin (Li et al., 2018; Tang et al., 2018). Various sedimentary systems within the faulted basin, including rivers, lakes, and alluvial fans, have influenced sediment deposition (Wang et al., 2020; Yu et al., 2023). The sedimentary facies of the Lower Wuerhe Formation have been classified into fan delta facies and lake facies. The sedimentary microfacies within the research area can be further classified into various types, including debris flow, braided channel, underwater distributary channel, estuarine sandbar, sheet sand, front fan delta, and semideep lake sedimentary microfacies (Hu et al., 2021; Wang et al., 2023). The evolution of these sedimentary facies exhibits a certain degree of continuity (He et al., 2018).

3 Methods

A total of 73 samples were collected from three wells, namely, D18, XY2, and YT1, containing the Permian Lower Wuerhe Formation. Thirty-seven samples were collected from Well D18, 16 samples were collected from Well XY2, and 20 samples were collected from Well YT1. The collection depths ranged from 4200 m to 5400 m, corresponding to deep to ultradeep layers, with layer thicknesses varying from 180 m to 1200 m.

All samples were finely ground into thin sections and subjected to microscopic examinations for rock and mineral identification to determine their mineral composition and structural characteristics. Additionally, 31 representative samples were subjected to microscopic pore observations via field emission scanning electron microscopy (FE-SEM) and electron probe microanalysis. Scanning electron microscopy was conducted at Hunan Nanomicro New Materials Technology Co., Ltd., in the laboratory, employing a Sirion 200 field emission scanning electron microscopy instrument, which operated at a voltage of 10 kV and offered a resolution of 1.5 nm.

Electron probe microanalysis was conducted at the Testing Center of the Shandong Bureau of the China Metallurgical Geology General Administration. The testing instrument that was used was the JXA-8230 (JEOL) electron probe analyzer, with a working voltage of 15 kV, a working current of 20 mA, and a beam spot of 2 μm.

The research area consists primarily of conglomerate formations. During the preparation of rock sample powders, all gravel components were systematically removed, allowing for the exclusive grinding of the matrix material into powder. The mineral mass fractions of 18 representative samples were determined through X-ray diffraction. Analyses were conducted at the Hunan Nano New Material Science and Technology Co., Ltd., laboratory, utilizing a D/MAX 2500 Diffractometer. The test conditions for the whole rock sample powder were as follows: a copper target, voltage of 40 kV, current of 80 mA, step width of 0.02°, and scanning range of 3° to 60°. Data processing and analysis were subsequently performed via Jade 6.0 software, which involved identifying and calculating the heights of various mineral diffraction peaks on the basis of the X-ray diffraction analysis method for clay minerals and common nonclay minerals in sedimentary rocks. This process enabled the identification of different mineral types.

Stable carbon‒oxygen (C‒O) isotope analyses were conducted at the State Key Laboratory of Endogenetic Metal Deposits Metallogenic Mechanism Research, Nanjing University, using a continuous flow mass spectrometer (MAT 253). The δ¹³C and δ¹⁸O values were measured by analyzing the CO₂ released from the samples and comparing them with the LAEAC01 standard. The samples were dissolved in an H₃PO₄ solution at 70°C for a minimum of 2 h. The error for the δ¹³C value was ± 0.03‰, and the error for the δ¹⁸O value was ± 0.08‰. The results are reported in units of per mil relative to the Pee Dee Belemnite (PDB).

4 Results

4.1 Lithofacies

The Wuerhe Formation on the northern slope of the central depression was formed in a fan delta sedimentary system (Zhang et al., 2015; Zhou et al., 2023). In Well XY2, the combined microfacies sequence from top to bottom represents the environments of an underwater distributary channel, sheet sands, an underwater distributary channel, an estuary sand dam, and a third underwater distributary channel (Fig. 2(a)). In Well YT1, the combined microfacies sequence from top to bottom consists of a pre-fan delta, an underwater distributary channel, sheet sands, a debris flow, a pre-fan delta, and a second debris flow (Fig. 2(b)). In Well D18, the combined microfacies sequence from top to bottom represents the environments of a semideep lake, a debris flow, sheet sands, an underwater distributary channel, and a second debris flow (Fig. 2(c)).

The debris flow sedimentary microfacies consists primarily of gray-black conglomerate and fine conglomerate. The thicknesses of a single layer range from 0.65 m to 1.5 m. Overall, the gravel clasts are relatively small in size, and the argillaceous content is low. The grains are poorly sorted and angular to subrounded.

The underwater distributary channel facies in the study area consist of gray thin argillaceous siltstone, siltstone, fine sandstone, coarse sandstone, gravel-bearing medium sandstone, and thin-layer conglomerate. The main lithology is medium- to coarse-grained sandstone, which originated from traction flow. The conglomerate has uniformly sized gravel and is particle supported, moderately sorted, and well rounded; in addition, it consists of mainly subcircular to subangular grains, and the conglomerate is massive in structure. Owing to the superposition of multistage channel sand bodies, the thickness can reach 4.87 m. This layer consists mostly of medium–fine sandstone, and the thickness of a single layer is not greater than 0.5 m.

The thicknesses of the sheet sand body are 0.2–2.2 m, and its lithologies are mainly gray siltstone, mixed fine sandstone, argillaceous siltstone, and mudstone. The particle sorting and rounding are poor, the grains are mainly subangular, and some of the siltstone features asphalt and block structures. Its bottom often abruptly contacts the coarse sandstone and gravel-bearing medium sandstone deposited in the underwater distributary channel microfacies.

The predelta subphase in the study area is mainly in Well YT1 and consists of gray-green, gray-black mudstone, argillaceous siltstone, and thin-layered gray-white siltstone. Horizontal bedding has developed, and the sedimentary thickness is approximately 3 m.

The semideep lake deposits in the study area are relatively developed. The lithology is gray‒black mudstone, with thicknesses of 0.15–2.0 m, and horizontal bedding has developed, reflecting the sedimentary characteristics of weak wave action in a lake.

Core observations indicate the presence of a fan delta front facies sandy conglomerate within the Lower Urho Formation in the study area, with the predominant rock types of the reservoir being greyish white massive gravelly gritstone and conglomerate (Figs. 2(a) and 2(b)). The cement content between rock debris particles is notably high, primarily consisting of zeolite cement with minor calcite (Figs. 3(c) and 3(d)). The cement type significantly impacts the reservoir; zeolite cement and carbonate cement are the main types observed. Zeolite cements are found mostly in the intergranular pores of sandy conglomerates, with coarser particles and less matrix (Figs. 3(e) and 3(f)).

Under microscopic examination, zeolite cement appears as plate-like or granular in structure, they are typically colorless or white and often exhibit complete cleavage. X-ray diffraction test data indicate that the overall mass fraction values of zeolite cement in the study area span from 1.48% to 23.34%, with an average content of approximately 9.74%.

There are multiple types of carbonate cements, including calcite, dolomite, and siderite, each with varying contents. The overall mass fraction values of carbonate cement range from 0.43% to 13.52%, with an average mass fraction of 3.61%. The average mass fraction content of the calcite cement is 2.06%, that of the dolomite cement is 0.97%, and that of the siderite cement is 0.58% (Table 1).

4.2 Geochemical characteristics

Electron probe analysis was conducted on zeolite samples obtained from Well D18 and Well XY2, which exhibit physical properties that are favorable in the study area. The analysis reveals average Na₂O contents of 0.207%, SiO₂ contents ranging from 49.651% to 55.727%, FeO and MnO contents of 0.052% and 0.006%, respectively, CaO contents ranging from 10.605% to 11.134%, and Al₂O₃ contents ranging from 20.59% to 21.89%, with an average content of 21.09%. The Si/Al ratios range from 2.398 to 2.691, and the average total content is 86.573% (Table 2). These components indicate that the zeolite in the study area is mainly laumontite, whereas the calcite is divided into early calcite and late calcite, which is consistent with the results of previous studies (Huang et al., 2015; Gao et al., 2017). FE-SEM analyses reveal that horizons with higher laumontite contents present a greater number of dissolution pores. These dissolution pores are well developed, manifesting as bay-shaped, serrated, and concave–convex-shaped structures, with evident signs of laumontite dissolution (Fig. 4).

4.3 Characteristics of the physical and reservoir space

4.3.1 Reservoir physical properties

The results of physical property testing of the core samples indicate that the porosities of the deep reservoirs within the Lower Wuerhe Formation in the study area range predominantly between 10% and 15% (Fig. 5(a)), with an average porosity of 10.67%. Ultralow-porosity reservoirs (porosity < 10%) account for 37.86% of the total reservoir volume, whereas low-porosity reservoirs (porosities ranging from 10% to 15%) comprise 53.21% (Fig. 5(b)). The reservoir permeabilities range primarily between 0 mD and 5 mD (Fig. 5(c)), with an average permeability of 12.17 mD. The medium-permeability reservoirs (50–500 mD) account for approximately 5.38%, the low-permeability reservoirs (5–50 mD) account for approximately 10.75%, and the tight reservoirs (< 5 mD) represent approximately 83.87% of the total. According to the Clastic Rock Reservoir’s Physical Property Classification Standard, the reservoirs within the Lower Wuerhe Formation are categorized as low-porosity and low-permeability reservoirs. In addition, the relationship between the porosity and depth of the deep reservoir of the Lower Wuerhe Formation reveals that at burial depths greater than 4500 m, there is still an abnormally high porosity zone (Fig. 5(d)) that deviates from the normal compaction curve.

4.3.2 Reservoir space characteristics

The reservoir contains a relatively high proportion of rock debris, with the visible volume fraction under the microscope averaging 45% and reaching a maximum of 60%. The composition is primarily tuff. The rock grains are predominantly subangular and subrounded, exhibit poor to medium sorting and are supported by a matrix. Additionally, the reservoir contains a high shale content and appears massive to thickly layered. The quartz and feldspar clasts have a combined particle size of approximately 30%, and their contact relationship is characterized primarily by concave–convex and linear contacts. Notably, there is significant mineral compression and fragmentation.

The thin sections and SEM images indicate close particle-to-particle contacts within the reservoirs. The primary type of reservoir space that is identified is dissolution pores (Fig. 6), followed by residual intergranular pores. Dissolution pores are primarily intergranular and intragranular dissolution pores, with diameters typically ranging from 50 μm to 500 μm. Intergranular dissolution pores, reaching up to 500 μm, are formed predominantly through the secondary enlargement of primary intergranular pores and are commonly connected to fractures. The edges of these pores exhibit a harbour-shaped, serrated, and concave‒convex structure (Fig. 6(a)), and they are distributed primarily near eroded rock debris and zeolite cement between rock debris particles (Fig. 6(b)). Intragranular dissolution pores result mainly from the selective dissolution of detrital particles (particularly feldspar) along cleavage planes or soluble components, with pore diameters typically ranging from approximately 50 μm to 100 μm. These pores are frequently linked with dissolution pores created by zeolite cement, displaying irregular harbour-like shapes with uneven edges (Fig. 6(c)). Some residual intergranular pores are observed, primarily representing spaces that remain after the primary intergranular pores undergo diagenetic evolution stages (Fig. 6(d)). These pores generally have diameters ranging from 50 μm to 200 μm and manifest as triangles, quadrilaterals, and irregular polygons (Figs. 6(e) and 6(f)). Microcracks can also be observed in several samples, resulting mainly from crack corrosion and expansion. Widths typically range from 10 μm to 20 μm. These cracks have a certain directionality, the ability to be filled, and corrosion expansion ability (Figs. 6(g) and 6(h)).

4.4 Characteristics of stable carbon and oxygen isotopes

To further investigate the mechanism of formation of dissolution pores, comprehensive whole-rock stable carbon and oxygen isotope analysis was conducted on representative samples from Wells D18, XY2, and YT1. The analysis reveals intriguing insights. The δ¹³C values range from −0.08‰ to −18.72‰ (V-PDB), whereas the δ¹⁸O values range from −19.19‰ to −13.25‰ (V-PDB) (Table 3). In particular, Well D18 exhibits δ¹³C values ranging from −15.34‰ to −17.60‰, Well XY2 displays δ¹³C values ranging from −11.30‰ to −14.29‰, and Well YT1 has δ¹³C values ranging from −1.80‰ to −8.69‰. These findings align with previous research findings (Fu et al., 2019; Zhang, 2021; Sun et al., 2023).

5 Discussion

5.1 The influence of sedimentation on pores

It is crucial to study the composition types of dissolution minerals under dominant sedimentary microfacies. Different sedimentary microfacies show significant differences. Statistical analysis was conducted on the porosity and permeability data obtained from three underground cored wells in the Wuerhe Formation: Well D18, Well XY2, and Well YT1. The analysis reveals the development of abnormally high-porosity zones within various sedimentary microfacies. The porosities of the conglomerates deposited by debris flows are primarily within 10% to 15%, with overall values ranging from 11.3% to 18.6% (Fig. 7(a)). The corresponding permeability values range from 0.01 mD to 458 mD (Fig. 8(a)). Similarly, for detrital flow deposits, the porosities range from 10% to 15%, with values ranging from 4.2% to 15.1% (Fig. 7(b)), and the permeability values range from 0.01 mD to 1428.2 mD (Fig. 8(b)), indicating the presence of samples with high permeability (> 500 mD). The underwater distributary channel deposits consist of conglomerate, gritstone, medium sandstone, and fine sandstone. The porosities in these deposits range primarily between 10% and 15%, with overall values ranging from 6% to 17% (Fig. 7(c)), and the corresponding permeabilities range from 0.01 mD to 80 mD (Fig. 8(c)). The porosities of the fine sheet sand siltstones range between 5% and 10%, with values ranging from 2.1% to 15.4% (Fig. 7(d)). The maximum permeability observed in this microfacies is 52.6 mD (Fig. 8(d)). These findings indicate that the physical properties of debris flow microfacies are the most favorable, followed by underwater distributary channel microfacies, whereas sheet sand microfacies exhibit relatively inferior physical properties.

5.2 Study of the dissolved components and sources of dissolution fluid

The formation of secondary pores through dissolution is the primary factor contributing to enhanced physical properties in deep reservoirs (Guo et al., 2017), underscoring the importance of studying their dissolution components. Therefore, the relationships among rock components, including zeolite, feldspar, and quartz contents, and the physical properties of the reservoir were analyzed. Overall, there is a positive correlation between the zeolite content and porosity/permeability (Figs. 9(a) and 9(b)). However, the correlations between the feldspar content and reservoir porosity and permeability are weak but positive (Figs. 9(c) and 9(d)). There is no significant correlation between the quartz content and reservoir porosity or permeability (Figs. 9(e) and 9(f)). These results suggest that zeolite is the primary dissolved component in reservoirs.

Moreover, the zeolite content and secondary pores are correlated (Figs. 9(a) and 9(b)). The significant presence of laumontite in the study area contributes to improved reservoir physical properties. The laumontite cement content in reservoirs is one of the principal factors controlling the physical properties of deep reservoirs.

An analysis of scatter plots depicting the whole-rock stable carbon and oxygen isotopes (Fig. 10(a)) provides valuable insights. The reservoir in Well D18 has the lowest δ¹³C values, whereas that in Well YT1 has the highest δ¹³C values. Well XY2, on the other hand, has values between those of the other two wells, i.e., intermediate δ¹³C values. This is due to the inability of atmospheric fresh water to affect carbon isotope values. Previous studies have classified the sources of carbon isotopes into salt carbonate genesis, organic acid decarboxylation, and biogenic gas genesis. The stable carbon isotope values of organic acids are usually −25‰, while the decarboxylation of organic acids can result in stable carbon isotope values less than 0‰ (Wang et al., 2021). The abnormal δ¹³C values indicate that the reservoir experienced dissolution by organic acid fluids during the later stages, resulting in the formation of numerous dissolution pores. Therefore, these findings suggest that Well D18 experiences prolonged interactions with organic acids, leading to a greater dissolution intensity. Well XY2 has a relatively moderate interaction intensity, whereas Well YT1 has the lowest intensity.

Finally, an analysis of the physical properties of these three representative drilling wells reveals fascinating results (Fig. 10(b)). The overall reservoir physical properties of Well D18 are the most favorable, followed by those of Well XY2, whereas Well YT1 has the least favorable physical properties. This result indicates that stronger contact between the reservoir and organic acid fluids is more likely to result in the development of high-quality reservoirs. Given the burial depth of approximately 4000 m in the research area, disregarding the impact of atmospheric precipitation on deep reservoirs is reasonable. Therefore, organic acid fluids have emerged as one of the key factors controlling the formation of high-quality deep reservoirs in the Lower Wuerhe Formation. In addition, the content of authigenic carbonate cement is not correlated with porosity or permeability, which implies that a significant quantity of calcite cement did not form during diagenesis (Fig. 10(c) and 10(d)).

5.3 Reservoir-forming mechanism

The Junggar Basin has a complex tectonic history and underwent many orogenic events, which undoubtedly affected the fractures and porosity and permeability characteristics of the reservoir rocks. However, through thin section identification and scanning electron microscopy analysis, the development of microcracks is not significant (Fig. 6). Overall, the debris flow microfacies are the dominant sedimentary microfacies. Frequent volcanic activity led to the devitrification of volcanic glass in volcanic rock debris-bearing glutenite and the formation of early unstable clinoptilolite (Weibel et al., 2019). Compaction caused by volcanic glass zeolitization, the formation of montmorillonite and cementation, such as calcareous cementation and zeolite cementation, are the main factors influencing the decrease in reservoir porosity. This also led to a rapid decrease in the porosity of the entire glutenite. As the burial of P₂w continued, the early clinoptilolite gradually underwent analcite formation and zeolitization, eventually transforming into laumontite and increasing the proportion of laumontite. With the continuous increase in organic acids produced by the development of source rocks, laumontite continued to undergo dissolution, and the decrease in deep reservoir pores was alleviated (Fig. 11), indicating that organic acids and zeolite cements do not play a destructive role in reservoir pores, such as those in medium–shallow reservoirs but play a key role in increasing the number of pores in deep reservoirs.

Deep reservoirs are routinely exposed to intense compaction throughout the burial phase. The overburden pressure prompts a rearrangement of rock grains, typically culminating in the near-total obliteration of primary pores, given that the pores are highly susceptible to collapse under such compressive forces. However, in deep reservoirs rich in zeolite, the widely dispersed cementitious substances in zeolite have provided significant support. They initiated a robust cementation process that occurred early in the sedimentary history. This cementation has bolstered the sediment’s ability to withstand compaction and, as a result, favored the preservation of primary pores. Zeolite acted as a protective framework that maintained the integrity of the pore structure. Concurrently, the presence of organic acids, which are commonly generated during the maturation of organic matter in source rocks, triggered significant dissolution within the reservoir. This dissolution represents a key controlling factor, as it causes an increase in a substantial number of secondary pores through chemical reactions with rock minerals. These secondary pores not only increase the overall porosity but also improve the pore connectivity. Consequently, the permeability of deep reservoirs has increased to a certain extent, thereby providing pathways for the migration of hydrocarbons. Collectively, the combined implications of these processes ultimately shape the characteristics and formation of deep reservoirs and govern their quality.

6 Conclusions

The deep reservoir lithology of the Permian Lower Wuerhe Formation in the central depression of the Junggar Basin is characterized primarily by greyish white massive gravelly gritstone and conglomerate. Within this region, deep, high-quality reservoirs are present, with zeolite cementation being the predominant cementation type and being abundantly distributed. The primary reservoir space is dominated by secondary dissolution pores. The debris flow microfacies exhibit the best physical properties among the deep reservoirs in the study area, followed by the underwater distributary channel microfacies, whereas the sheet sand microfacies present the least favorable physical properties.

Diagenesis in the study area is characterized primarily by compaction, cementation, and dissolution. Strong compaction adversely affects the development of primary pores and significantly hinders the physical properties of reservoirs. Conversely, the dissolution process yields dissolution pores that greatly enhance the physical properties of the reservoir. Zeolite cement, which is composed primarily of laumontite, plays a significant role in deep reservoirs. The laumontite content is positively correlated with reservoir physical properties, exerting a substantial influence on the physical properties of deep reservoirs in the study area. The fluids involved in dissolution responsible for the deep reservoirs in the study area are organic acids. The greater the dissolution strength of the deep reservoir is, the better the physical properties of the reservoir. Sedimentation and diagenesis are the main factors controlling the physical properties of deep reservoirs in the study area.

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